In-situ combustion (ISC) is a promising enhanced oil recovery process for the vast heavy oil accumulation of the Orinoco Belt in Venezuela. Combustion tube tests were performed to assess the feasibility of the process in a reservoir of the area. Given the successful laboratory results, it was decided to proceed with the design of a pilot test. Along with the basic design calculations, a simulation model was built to aid in selecting optimum well locations and operating strategies of the pilot. This would also be used for history matching of the actual operation and further optimization. One of the features of the model is the inclusion of the foamy oil behavior exhibited by the oil. For the modeling of the combustion process, a kinetic model developed in-house by PDVSA Intevep using thermo-gravimetric and scanning calorimetry experiments from an analog field, was employed. The first stage of the study involved the characterization of the oil into the same pseudo-components utilized by the kinetic model. A match of relevant PVT data was done for this purpose. In the second stage, the field scale model was history matched with the new fluid model, which included the foamy oil behavior. The best agreement with field measured data was obtained with a dispersed-gas foamy oil model with velocity dependence of the reaction that converts the low-mobility dispersed gas into high-mobility free gas. The following stage consisted of the history match of the combustion tube test, which was partly achieved with an assisted-history-matching tool. In the last stage, the results obtained from the combustion tube match were applied to the field model. In order to determine the most appropriate locations of production and injection wells, several pilot configurations were studied combining vertical and horizontal wells. A sensitivity analysis was completed using operational parameters such as injection rates and distance between producers and injectors wells. Based on ultimate recovery, the best pattern configuration was selected along with the optimum operational parameters. This paper illustrates the application of a workflow for modeling ISC from laboratory experiments to the field scale.

The In Situ Combustion Pilot Project (ISCPP) to be carried out in the Orinoco Oil Belt (Venezuela), is a technological project leaded by PDVSA Intevep together with several organizations of PDVSA E&P San Tomé. ISCPP is oriented towards the assessment of such thermal process in the increase of recovery factors in heavy (H) and extra heavy (XH) crude oil reservoirs. Although the Orinoco Oil Belt was discovered in the 1930s, it was in the 1980s that the first rigorous evaluations were made. Recently, the area was certificated to contain 235 billions of recoverable (20% of recovery factor) barrels of heavy and extra heavy oil. The ISCPP will allow the study and development of new technologies that increase the current recovery factor in the world’s largest H/XH oil reservoir. This work covers all of disciplines considered in the project, mainly: The analysis of lab combustion tests using two kinds of cells both prepared with sand and saturated with water and XH crude oil at reservoir conditions.The static and dynamic reservoir simulations using Petrel and Star respectively.The design, construction and completion of producers, observers and air injection wells.The study, analysis and development of surface facilities and the gas treatment system and monitoring, which must have to take care of relevant quantities of contaminant gases such as SO2, H2S and CO. Based on this study, the technical and economical feasibility analyses were completed. The cold production is expected to begin during first semester of 2011, while the thermal phase involving air injection, which is the aim of the project, will be implemented throughout the second semester 2011.

Pursuing new alternatives to develop and produce sands B1 and B4 together, belonging to the reservoir VLG-3729 of Moporo Field located in western Venezuela, different exploitation schemes were evaluated, where intelligent completions have been highlighted. A pilot well with inflow control valves (ICVs) was proposed with the goal of maximizing the well oil production, avoiding cross-flow, minimizing operational risks and well interventions(coil-tubing operations), leading to better reservoir management. To evaluate the intelligent completion technology, an Integrated Asset Model (IAM) was implemented. This model was divided in two sections: the first section involves the reservoir model using a reservoir simulator, which includes the representation of the ICVs through the multi-segment wells option; the second section represents the fluid flow in the well and pipelines from the couple point to the sink including the artificial lift system (Electrical Submersible Pump, ESP) through a network simulator. Both sections were coupled taking an intermediate point between the ESP and ICVs as a coupled node. The differences using a stand alone model and a coupled model were analyzed. Given that in both models the main constraints are handled in different ways, the calculated liquid production trend is different for each model. The stand alone model is constrained by maximum liquid rate and minimum bottom hole pressure (BHP), while the BHP constraints on the coupled model is calculated dynamically by the production system. In this case, the stand alone reservoir model leads to an optimistic production profile. These results show the advantage in the use of an IAM, taking into account the network constraints to obtain more accurate results. To evaluate the performance of the smart well, several sensitivities to the coupled model were made, changing the opening valves position at the beginning of the forecast. An increment in the cumulative oil production was observed when the cross flow between sands were not allowed. Introduction The VLG-3729 Moporo field is located between Zulia and Trujillo states (Western of Venezuela). It was discovered in 1988 by an advanced well (VLG-3729) from a neighbor reservoir. See Fig. 1. Six regions are defined by two primary faults and several secondary faults, which have compartmentalized the field. The depths vary from 15000 and 17000 ft, initial pressure of 7500 psi, net thickness from 400 to 500 ft, porosity from 10 to 15% and effective permeability from 50 to 500 md. It represents the most prolific and potential field from Maracaibo Basin. Moporo field has a cumulative production at 320 MMSTB under natural depletion with reservoir temperatures range from 280 to 300 °F and 22 °API approximately. The field development currently consists of 96 wells (88 active, 5 inactive and 3 abandoned wells), which produce from two separated reservoirs: B-1 and B-4. B1 sand is under initial conditions with a 3500 STB/d as estimated potential, whereas B4 sand accounts 90% of total production with an initial production from 6000 STB/d. The driven mechanism has been identified as solution gas and water drive.

La Cira Infantas (LCI) is the oldest oilfield in Colombia, with 100 years of oil production history spanning three periods: primary depletion, the first waterflood (WF) period, and the second WF period. After the first WF period, the field had neared its economic limit and an abandonment program was underway from 2003 to 2005. Partners Ecopetrol and Occidental made the decision to implement a waterflood redevelopment project in 2005 that included reconfiguration of the old WF areas and WF expansion into new areas. The partners formed integrated reservoir development and management teams (RDT and RMT) that have combined workovers, infill drilling, WF optimization, and other IOR/EOR methods. The oil production has increased from approximately 5,000 to over 43,000 bopd, which is above the predicted 40,000 bopd. One of the key components was WF conformance controls to improve sweep efficiency and to improve injection profiles across multiple stacked-sand layers. The selective injection method was implemented using multiple packers and side-pocket mandrels/valves. The design of selective injection strings involved complex engineering calculations and left some room for improvement. This paper describes a new workflow used to optimize the selective injection design using multiphase flow simulation based on actual WF patterns. A field pilot test used an inverted 5-spot WF pattern to demonstrate this new workflow. The simulation results predicted a 45% incremental oil production above the base case. The simulation optimization process reduced the number of mandrels/valves from nine to six, which saves about 30% of the associated completion costs compared with the initial completion proposal for this case study.

The efficient and economic recovery of heavy oil and bitumen is a mayor technical challenge due to their high viscosity. In the Orinoco Oil Belt, due to the high viscosity, different thicknesses and heterogeneities found, thermal recovery processes have demonstrated to be the best alternative for the enhancement and acceleration of heavy oil recovery. Bare Field, with an average API gravity of 10°, is among the fields of the Orinoco Oil Belt where thermal recovery has been applied through the implementation of Cyclic Steam Injection in horizontal wells, with substantial productivity increase. This led to the introduction of the first SAGD (Steam Assisted Gravity Drainage) pilot project on the Orinoco Oil Belt, on the Bare Field, this pilot test is in operation from 2009, and the recovery factor of the area affected by the steam is estimated to increase from 14 to 60 % The location and design of these SAGD wells was accomplished using independents models for reservoir, well and surface, creating a production scenario without taking into account the interaction between models. A dynamic coupling of the reservoir simulation model with the well and surface models allows the consideration of more realistic boundary conditions. In this sense, an integrated model was developed in the present work, allowing the dynamic evaluation of the entire system helping to understand the energy consumption along the system to improve the recovery method performance. To develop this model, a dynamic thermal reservoir model was created from an existing static model of the reservoir. Once the reservoir model was able to reproduce the flow rates, pressure and temperature with acceptable accuracy compared to the real history data, the next step was the elaboration of well models. The reservoir and well models were coupled in one model to evaluate the advantages of use integrated models for the evaluation of the energetic efficiency of SAGD projects.